Fluids are frequently tested in a laboratory to obtain a rough estimate of the fluid's lubricity before the fluid is used in the oilfield. It is important that the laboratory measurements of lubricity reliably correlate to the lubricity observed in the field. For example, operators depend on reliable lubricity coefficients as input into computer drilling models to predict drillstring loads to optimize casing runs, to enhance the well design with respect to torque and drag, to recommend proper mud systems, determine the optimum lubricant amounts, to develop new lubricant additives, and the like.
Lubricity is a measure of the coefficient of friction between a moving part and a surface in contact with the part. The lower the coefficient of friction, the greater the lubricity. The coefficient of friction, p, is defined as the ratio of the force, F, required to move an object in contact with a surface to the force, W1, pushing downward or perpendicular to the object: μ=F/W1. The coefficient of friction may alternatively be called the friction coefficient, friction factor, or the lubricity coefficient.
Lubricity of a material cannot be directly measured, so tests are performed to quantify a lubricant or fluid performance. By determining the friction between the surfaces, the lubricity may be determined. For example, the lubricity may be determined by determining how much wear is caused to a surface by a given friction-inducing surface to another surface in a given amount of time under particular conditions, e.g. surface size, temperature, pressure, etc. More wear to a surface indicates a worse lubricity. For this reason, lubricity is also termed a substance's anti-wear property. Non-limiting examples of current apparatuses to test lubricity used by those skilled in the art include “ball-on-cylinder” and “ball-on-three-discs” tests.
A substantial portion of the time required for well intervention operations, drilling operations, completion operations, and/or fracturing operations is consumed in replacing worn metal pieces and/or equipment used for these tasks. Excessively high torque and drag may cause costly delays or interruptions during downhole operations. The metal surfaces also wear down due to frictional forces, resulting in reduced equipment life. These problems generally increase at high temperatures and/or high pressures.
Lubricants or lubricating agents may be added to a fluid to reduce or decrease friction, torque, and/or drag between two surfaces. This may be especially important when one or both surfaces are metal surfaces, such as within and/or around coiled tubing used during coiled tubing operations. Coiled tubing is used in the oil and gas industry for interventions in oil and gas wells, as production tubing in depleted gas wells, and/or for similar operations to wirelining. Chemicals may be pumped through the coiled tubing and may be pushed into the hole instead of relying only on gravity to get the chemicals into the hole. Coiled tubing is a metal piping typically ranging in diameter from about 0.5 inch to about 5 inches depending on the coiled tubing operation.
The fluids may be drilling fluids, completion fluids, fracturing fluids, etc. Drilling fluids are typically classified according to their base fluid. In water-based fluids, solid particles are suspended in a continuous phase including water or brine. Oil can be emulsified in the water, which is the continuous phase. “Water-based fluid” is used herein to include fluids having an aqueous continuous phase where the aqueous continuous phase can be all water or brine, an oil-in-water emulsion, or an oil-in-brine emulsion. Brine-based fluids, of course are water-based fluids, in which the aqueous component is brine.
Oil-based fluids are the opposite or inverse of water-based fluids. “Oil-based fluid” is used herein to include fluids having a non-aqueous continuous phase where the non-aqueous continuous phase is all oil, a non-aqueous fluid, a water-in-oil emulsion, a water-in-non-aqueous emulsion, a brine-in-oil emulsion, or a brine-in-non-aqueous emulsion. In oil-based fluids, solid particles are suspended in a continuous phase including oil or another non-aqueous fluid. Water or brine can be emulsified in the oil; therefore, the oil is the continuous phase. In oil-based fluids, the oil may include any oil or water-immiscible fluid that may include, but is not limited to, diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins.
Oil-based fluid as defined herein may also include synthetic-based fluids or muds (SBMs), which are synthetically produced rather than refined from naturally occurring materials. Synthetic-based fluids often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types.
There are a variety of functions and characteristics that are expected of completion fluids. The completion fluid may be placed in a well to facilitate final operations prior to initiation of production. Completion fluids are typically brines, such as chloride brines, bromide brines, formate brines, but may be any non-damaging fluid having proper density and flow characteristics. Suitable salts for forming the brines include, but are not necessarily limited to, sodium chloride, calcium chloride, zinc chloride, potassium chloride, potassium bromide, sodium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, ammonium formate, cesium formate, and mixtures thereof.
Chemical compatibility of the completion fluid with the reservoir formation and fluid is key. Chemical additives, such as polymers and surfactants are known in the art for being introduced to the brines used in well servicing fluids for various reasons that include, but are not limited to, increasing viscosity, and increasing the density of the brine. Water-thickening polymers serve to increase the viscosity of the brines and thus retard the migration of the brines into the formation and lift drilled solids from the wellbore. A regular drilling fluid is usually not compatible for completion operations because of its solid content, pH, and ionic composition.
Completion fluids also help place certain completion-related equipment, such as gravel packs, without damaging the producing subterranean formation zones. The completion fluid should be chemically compatible with the subterranean reservoir formation and its fluids.
A fracturing fluid may be injected into a well as part of a stimulation operation. Fracturing fluids may include water, proppant, and a small amount of non-aqueous fluids designed to reduce friction pressure while pumping the fluid into the wellbore. Such fluids often include gels, friction reducers, crosslinkers, and/or breakers to reduce the viscosity of the gel, and surfactants. The type of additive added to the fracturing fluid is selected depending on the needs for improving the stimulation operation and the productivity of the well.
A drill-in fluid may be used exclusively for drilling through the reservoir section of a wellbore successfully, which may be a long, horizontal wellbore. The drill-in fluid may minimize damage and maximize production of exposed zones, and/or facilitate any necessary well completion. A drill-in fluid may be a fresh water or brine-based fluid that contains solids having appropriate particle sizes (salt crystals or calcium carbonate) and polymers. Filtration control additives and additives for carrying cuttings may be added to a drill-in fluid.
A workover fluid is a fluid for repairing or stimulating an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons. A well intervention operation is any operation carried out on an oil or gas well during or at the end of its productive life that alters the state of the well and/or the well geometry, provides well diagnostics, or manages the production of the well. Such operations may include logging, gauging, plugging, re-perforating, and/or various downhole mechanical operations to reduce flow restrictions when trying to obtain additional production volume from a well.
Therefore, it would be desirable if a lubricity testing apparatus that simulates the conditions under which fluids used for various operations (e.g. coiled tubing operations) function to measure the effectiveness of a lubricant against drag and other frictional resistance forces encountered in such operations. It would also be beneficial for the lubricity testing apparatus to test a fluid under dynamic conditions that are more closely encountered in the field.